EP0389150A1 - Removal of sulphides - Google Patents
Removal of sulphides Download PDFInfo
- Publication number
- EP0389150A1 EP0389150A1 EP90302513A EP90302513A EP0389150A1 EP 0389150 A1 EP0389150 A1 EP 0389150A1 EP 90302513 A EP90302513 A EP 90302513A EP 90302513 A EP90302513 A EP 90302513A EP 0389150 A1 EP0389150 A1 EP 0389150A1
- Authority
- EP
- European Patent Office
- Prior art keywords
- chlorite
- composition according
- composition
- sulphide
- amphoteric compound
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
- 150000003568 thioethers Chemical class 0.000 title abstract 2
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 claims abstract description 29
- 238000005260 corrosion Methods 0.000 claims abstract description 29
- 230000007797 corrosion Effects 0.000 claims abstract description 29
- 239000000203 mixture Substances 0.000 claims abstract description 29
- 229910001919 chlorite Inorganic materials 0.000 claims abstract description 24
- 229910052619 chlorite group Inorganic materials 0.000 claims abstract description 24
- QBWCMBCROVPCKQ-UHFFFAOYSA-N chlorous acid Chemical compound OCl=O QBWCMBCROVPCKQ-UHFFFAOYSA-N 0.000 claims abstract description 24
- 239000003112 inhibitor Substances 0.000 claims abstract description 13
- 238000000034 method Methods 0.000 claims abstract description 7
- 239000007864 aqueous solution Substances 0.000 claims abstract description 4
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 claims description 13
- 150000001875 compounds Chemical class 0.000 claims description 12
- 239000002516 radical scavenger Substances 0.000 claims description 10
- 239000000356 contaminant Substances 0.000 claims description 9
- KWIUHFFTVRNATP-UHFFFAOYSA-N Betaine Natural products C[N+](C)(C)CC([O-])=O KWIUHFFTVRNATP-UHFFFAOYSA-N 0.000 claims description 7
- 239000000126 substance Substances 0.000 claims description 7
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 6
- -1 alkali metal chlorite Chemical class 0.000 claims description 5
- 229960003237 betaine Drugs 0.000 claims description 5
- 125000000623 heterocyclic group Chemical group 0.000 claims description 5
- 229940094506 lauryl betaine Drugs 0.000 claims description 4
- DVEKCXOJTLDBFE-UHFFFAOYSA-N n-dodecyl-n,n-dimethylglycinate Chemical compound CCCCCCCCCCCC[N+](C)(C)CC([O-])=O DVEKCXOJTLDBFE-UHFFFAOYSA-N 0.000 claims description 4
- 238000012545 processing Methods 0.000 claims description 4
- 125000000217 alkyl group Chemical group 0.000 claims description 3
- 229910052757 nitrogen Inorganic materials 0.000 claims description 3
- 125000004433 nitrogen atom Chemical group N* 0.000 claims description 3
- 125000006686 (C1-C24) alkyl group Chemical group 0.000 claims description 2
- 125000004178 (C1-C4) alkyl group Chemical group 0.000 claims description 2
- 229910052783 alkali metal Inorganic materials 0.000 claims description 2
- 125000003545 alkoxy group Chemical group 0.000 claims description 2
- 125000003118 aryl group Chemical group 0.000 claims description 2
- 229910052736 halogen Inorganic materials 0.000 claims description 2
- 150000002367 halogens Chemical class 0.000 claims description 2
- 125000005842 heteroatom Chemical group 0.000 claims description 2
- 125000002887 hydroxy group Chemical group [H]O* 0.000 claims description 2
- 125000002636 imidazolinyl group Chemical group 0.000 claims description 2
- 239000007788 liquid Substances 0.000 claims description 2
- 230000003647 oxidation Effects 0.000 claims description 2
- 238000007254 oxidation reaction Methods 0.000 claims description 2
- 238000003860 storage Methods 0.000 claims description 2
- 125000001424 substituent group Chemical group 0.000 claims description 2
- BDHFUVZGWQCTTF-UHFFFAOYSA-N sulfonic acid Chemical group OS(=O)=O BDHFUVZGWQCTTF-UHFFFAOYSA-N 0.000 claims description 2
- 150000003868 ammonium compounds Chemical class 0.000 abstract 1
- 239000010779 crude oil Substances 0.000 description 11
- 238000002347 injection Methods 0.000 description 10
- 239000007924 injection Substances 0.000 description 10
- UKLNMMHNWFDKNT-UHFFFAOYSA-M sodium chlorite Chemical compound [Na+].[O-]Cl=O UKLNMMHNWFDKNT-UHFFFAOYSA-M 0.000 description 9
- 239000000243 solution Substances 0.000 description 9
- 230000000694 effects Effects 0.000 description 6
- 238000002474 experimental method Methods 0.000 description 6
- 238000009472 formulation Methods 0.000 description 5
- 238000004519 manufacturing process Methods 0.000 description 5
- OSVXSBDYLRYLIG-UHFFFAOYSA-N dioxidochlorine(.) Chemical compound O=Cl=O OSVXSBDYLRYLIG-UHFFFAOYSA-N 0.000 description 4
- 238000005259 measurement Methods 0.000 description 4
- 150000004763 sulfides Chemical class 0.000 description 4
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 3
- 239000006227 byproduct Substances 0.000 description 3
- 239000012530 fluid Substances 0.000 description 3
- 239000003921 oil Substances 0.000 description 3
- 239000007800 oxidant agent Substances 0.000 description 3
- 229920001343 polytetrafluoroethylene Polymers 0.000 description 3
- 239000000047 product Substances 0.000 description 3
- 230000002000 scavenging effect Effects 0.000 description 3
- 229910000030 sodium bicarbonate Inorganic materials 0.000 description 3
- 229960002218 sodium chlorite Drugs 0.000 description 3
- 229910000975 Carbon steel Inorganic materials 0.000 description 2
- 239000004155 Chlorine dioxide Substances 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- 108091006629 SLC13A2 Proteins 0.000 description 2
- UIIMBOGNXHQVGW-UHFFFAOYSA-M Sodium bicarbonate Chemical compound [Na+].OC([O-])=O UIIMBOGNXHQVGW-UHFFFAOYSA-M 0.000 description 2
- QAOWNCQODCNURD-UHFFFAOYSA-N Sulfuric acid Chemical compound OS(O)(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-N 0.000 description 2
- 239000012267 brine Substances 0.000 description 2
- 238000006243 chemical reaction Methods 0.000 description 2
- 235000019398 chlorine dioxide Nutrition 0.000 description 2
- VDQVEACBQKUUSU-UHFFFAOYSA-M disodium;sulfanide Chemical compound [Na+].[Na+].[SH-] VDQVEACBQKUUSU-UHFFFAOYSA-M 0.000 description 2
- 239000007789 gas Substances 0.000 description 2
- 238000011065 in-situ storage Methods 0.000 description 2
- 239000003129 oil well Substances 0.000 description 2
- 239000000376 reactant Substances 0.000 description 2
- 150000003839 salts Chemical class 0.000 description 2
- 239000011780 sodium chloride Substances 0.000 description 2
- 229910052979 sodium sulfide Inorganic materials 0.000 description 2
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 2
- 235000011149 sulphuric acid Nutrition 0.000 description 2
- 239000001117 sulphuric acid Substances 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- ZAMOUSCENKQFHK-UHFFFAOYSA-N Chlorine atom Chemical compound [Cl] ZAMOUSCENKQFHK-UHFFFAOYSA-N 0.000 description 1
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 description 1
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 1
- 229910001209 Low-carbon steel Inorganic materials 0.000 description 1
- 239000004677 Nylon Substances 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- 239000000654 additive Substances 0.000 description 1
- 230000000996 additive effect Effects 0.000 description 1
- 239000010962 carbon steel Substances 0.000 description 1
- 239000013626 chemical specie Substances 0.000 description 1
- 239000000460 chlorine Substances 0.000 description 1
- 229910052801 chlorine Inorganic materials 0.000 description 1
- 238000010960 commercial process Methods 0.000 description 1
- 238000005336 cracking Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- 238000010348 incorporation Methods 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 230000009972 noncorrosive effect Effects 0.000 description 1
- 229920001778 nylon Polymers 0.000 description 1
- 230000002572 peristaltic effect Effects 0.000 description 1
- 150000002978 peroxides Chemical class 0.000 description 1
- 239000002244 precipitate Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 238000000926 separation method Methods 0.000 description 1
- 229920002379 silicone rubber Polymers 0.000 description 1
- 239000004945 silicone rubber Substances 0.000 description 1
- 235000017557 sodium bicarbonate Nutrition 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 125000006850 spacer group Chemical group 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 231100000331 toxic Toxicity 0.000 description 1
- 230000002588 toxic effect Effects 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
- C10G27/02—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with halogen or compounds generating halogen; Hypochlorous acid or salts thereof
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
- Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10S507/00—Earth boring, well treating, and oil field chemistry
- Y10S507/927—Well cleaning fluid
Definitions
- the present invention relates to a process for the removal of sulphides, especially hydrogen sulphide present in a crude oil or hydrocarbon feed contaminated therewith during production or processing of said feed or in water separated from said feed.
- Sulphides in general and hydrogen sulphide in particular is an undesirable by-product of crude oil production. These sulphides are toxic, have an obnoxious odour and, in the case of wet hydrogen sulphide, is highly corrosive to carbon steel.
- R.N. Tuttle et al describe the corrosive aspects of hydrogen sulphide in relation to high strength steels in "H2S corrosion in Oil and Gas Production", National Association of Corrosion Engineers, 1981.
- chlorite including chlorine dioxide
- the present invention is a composition suitable for use as a sulphide scavenger, said composition comprising an aqueous solution of a chlorite and a corrosion inhibitor, characterised in that the corrosion inhibitor is an amphoteric compound of the formula wherein each of R1, R2 and R3 is the same or different group selected from H, C1-C24 alkyl, aryl, halogen, hydroxy, alkoxy, carbonylic and a heterocyclic group formed by a combination of at least two of R1, R2 and R3 and the nitrogen atom, said heterocyclic group optionally containing additional heteroatoms, R4 is a carboxylic or a sulphonic acid group, and n has a value from 1-9.
- the corrosion inhibitor is an amphoteric compound of the formula wherein each of R1, R2 and R3 is the same or different group selected from H, C1-C24 alkyl, aryl, halogen, hydroxy, alkoxy, carbonylic and a heterocyclic group formed
- the sulphide contaminant to be scavenged may be present in liquid or gaseous streams or in storage tanks forming part of a chemicals processing plant, e.g. crude oil processing.
- the contaminant may be present, for instance, in (i) a crude oil feed which is either in an untreated virgin state as recovered from an oil well, or (ii) a feed that has undergone one or more preliminary treatment stages, whether physical or chemical, prior to any cracking step to which the crude oil is subjected, or (iii) an aqueous feed derived as a by-product of chemical manufacturing including crude oil recovery, whether or not associated with crude oil recovered from an oil well.
- the feed may be crude oil derived or recovered directly from the well or that at any stage immediately prior to the gas/oil separation step, whether or not associated with water.
- the type of chlorite used may be any chlorite which is soluble in water.
- the chlorites are suitably alkali metal chlorites, preferably sodium chlorite.
- the amount of the chlorite present in the composition will depend upon the extent to which the sulphide contaminant is to be removed. The precise amount used would depend upon the nature of the sulphide to be removed and the type of feed. Thus for full removal of the sulphide contaminant in a feed, the chlorite is preferably used in an amount of at least 0.5 moles per mole of the sulphide contaminant to be removed.
- R1 and R3 are suitably C1-C4 alkyl groups, preferably CH3;
- R2 is suitably a C10-C15 alkyl group, preferably C12-C14 alkyl group;
- R4 is suitably a -C00- group; and
- n is suitably 1-4, preferably 1-2.
- the ring so formed is suitably an imidazoline ring.
- amphoteric compound used is most preferably an alkyl betaine, especially lauryl betaine.
- the relative proportions of the chlorite and the ampholeric compound in the composition is suitably in the range of 1:0.1 to 1:0.9 w/w respectively, preferably 1:0.4 to 1:0.7 w/w.
- compositions of the present invention are preferably used as aqueous solutions.
- such solutions may optionally contain a water-miscible secondary solvent, e.g. an alcohol or a glycol to enhance the freeze-thaw properties of the composition.
- a water-miscible secondary solvent e.g. an alcohol or a glycol to enhance the freeze-thaw properties of the composition.
- the treatment of the contaminated feed with the compositions of the present invention can be effected at temperatures ranging from below ambient to about 150°C.
- the scavenger formulations of the present invention are particularly effective in treating wet crude oil, i.e. crudes containing 5 - 95% w/w water and containing hydrogen sulphide at levels of 1 - 1000 ppm at a temperature e.g. in the range from 15-60°C and a pH e.g. in the range of 4.0-6.9. These formulations are substantially free of any corrosive effects under these conditions.
- a feature of the present inventions is that the use of these scavenger formulations have significant advantages over those used hitherto: For instance these compositions are:
- Corrosion rate measurements were performed using LPR (linear polarisation resistance) method.
- a rig was constructed from polytetrafluroethylene (PTFE), nylon and silicone rubber.
- the rig contained two separate corrosion cells, connected in series but some distance apart. Each cell contained three concentric, mild steel electrodes, 8.6cm2 surface area, with PTFE spacers.
- a multichannel peristaltic pump controlled the addition of all the chemicals through the rig. Concentrations of the various reactants were adjusted to give the desired final concentration of sulphide and scavenger composition in the flowing stream. A flow rate of 45 to 50cm3 (total fluids) was set. Deareated saline water (4.3% NaCl) buffered to a pH of 4.8 with NaHCO3 and CO2 was treated with 35 to 40ppm w/w (in fluid) of H2S. Corrosion rate measurements were continuously monitored at the point of injection, cell A, and further downstream, cell B. In this way the most corrosive environment (highest excess of oxidising agent) and the least corrosive environment (dynamic equilibrium of reactants) were obtained. Sample points of the untreated and the treated H2S stream enabled assessment of the efficiency of the H2S scavenging reaction (Iodimetric analysis, see Vogel's Textbook of Quantitative Inorganic Analysis, 4th Edition, Longmans).
- Table 1 The effect of the injection of a solution that contains only sodium chlorite is shown in Table 1.
- the corrosion rate does not increase above that of the background until the level of the scavenger equals that required to react with all the hydrogen sulphide at this concentration the corrosion rate in the injection cell increases significantly although the downstream corrosiveness is still that of the background. Above this concentration the corrosion rate increases to unacceptable levels.
- Table 2 shows that by incorporating a betaine into the formulation the corrosion rate is controlled to less than 30 mpy even when the injection rate is double that required to react with all the hydrogen sulphide.
- Chlorite has been tested with and without lauryl betaine to investigate the influence if any of the corrosion inhibitor on the hydrogen sulphide scavenging ability of the product.
- Hydrogen sulphide was generated in situ in a sealed vessel containing brine (92cm3 of 4% NaC1, 0.1% NaHC03) and stabilised crude oil (10cm3 of forties crude), by injection of an aqueous Na2S solution (2.6cm3 of 0.029M) and sulphuric acid (5.6cm3 of 0.05m).
- the resultant pH was 6.2 to 6.4.
- the H2S scavenger was introduced into the flask and after a predetermined time interval the residual H2S was determined by injection of 100cm3 of air through the solution and vented via a Drager tube. Experiments were all conducted at ambient temperatures.
- Chlorite has been tested with and without lauryl betaine to investigate the influence if any of the corrosion inhibitor on the hydrogen sulphide scavenging ability of the product.
- Hydrogen sulphide was generated in situ in a sealed vessel containing brine (92cm3 of 4% NaC1, 0.1% NaHC03) and stabilised crude oil (10cm3 of forties crude), by injection of an aqueous Na2S solution (2.6cm3 of 0.029M) and sulphuric acid (5.6cm3 of 0.05m).
- the resultant pH was 6.2 to 6.4.
- the H2S scavenger was introduced into the flask and after a predetermined time interval the residual H2S was determined by injection of 100cm3 of air through the solution and vented via a Drager tube. Experiments were all conducted at ambient temperatures.
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- Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Engineering & Computer Science (AREA)
- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
- Organic Chemistry (AREA)
- Preventing Corrosion Or Incrustation Of Metals (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
Description
- The present invention relates to a process for the removal of sulphides, especially hydrogen sulphide present in a crude oil or hydrocarbon feed contaminated therewith during production or processing of said feed or in water separated from said feed.
- Sulphides in general and hydrogen sulphide in particular is an undesirable by-product of crude oil production. These sulphides are toxic, have an obnoxious odour and, in the case of wet hydrogen sulphide, is highly corrosive to carbon steel. R.N. Tuttle et al describe the corrosive aspects of hydrogen sulphide in relation to high strength steels in "H₂S corrosion in Oil and Gas Production", National Association of Corrosion Engineers, 1981.
- In view of the above various commercial processes of removing hydrogen sulphide are used as add-on "sweetening" units for the treatment of the so called "sour" crudes. Such "sweetening" units of plants are, however, unattractive due to space or weight limitations especially on off-shore installations. Moreover, the economics of such units are often unfavourable.
- Attempts have been made to develop a chemical injection formulation which would react rapidly with the sulphides without giving rise to any undesirably side-effects. Most of the systems of this type now available are based on chlorine or peroxide chemistry. Unfortunately these chemicals are invariably strong oxidising agents and are also fairly corrosive to carbon steels, especially if the oxidising agent is present in excess of the amount required to react with the sulphide contaminant. Hence additional corrosion inhibitors may have to be incorporated in such systems to mitigate the corrosive effects of the additive.
- One of the most successful chemical species that has been investigated as a sulphide scavenger is a chlorite (including chlorine dioxide). Products based on this active species have been shown both in the laboratory and when used on oil production platforms to react quickly and efficiently with any hydrogen sulphide present. The chemical reaction of chlorite with hydrogen sulphide is given below:
C10₂⁻ + 2H₂S = C1⁻ + 2H₂0 + 2S - However, the use of chlorite and its salts or chlorine dioxide on their own causes the corrosivity of the produced fluids to increase markedly especially when used at an injection rate over and above that required to react with all the hydrogen in such systems to mitigate this undesirable effect. This must be added separately since most of the commonly-used corrosion inhibitors are either incompatible with chlorite due to its very strong oxidising potential or form insoluble precipitates of cannot be used offshore for environmental reasons e.g. Cr salts.
- It has now been found that most of the above problems can be mitigated using specific scavengers which either react with or otherwise render the sulphide contaminent harmless.
- Accordingly, the present invention is a composition suitable for use as a sulphide scavenger, said composition comprising an aqueous solution of a chlorite and a corrosion inhibitor, characterised in that the corrosion inhibitor is an amphoteric compound of the formula
- The most common volatile sulhpide found as contaminant in such feeds is hydrogen sulphide.
- The type of chlorite used may be any chlorite which is soluble in water. Thus, the chlorites are suitably alkali metal chlorites, preferably sodium chlorite.
- The amount of the chlorite present in the composition will depend upon the extent to which the sulphide contaminant is to be removed. The precise amount used would depend upon the nature of the sulphide to be removed and the type of feed. Thus for full removal of the sulphide contaminant in a feed, the chlorite is preferably used in an amount of at least 0.5 moles per mole of the sulphide contaminant to be removed.
- The substituent groups in the amphoteric compounds of formula (I) are suitably such that they are resilient to oxidation by the chlorite component in the composition. Thus in the amphoteric compounds of formula (I) R₁ and R₃ are suitably C₁-C₄ alkyl groups, preferably CH₃; R₂ is suitably a C₁₀-C₁₅ alkyl group, preferably C₁₂-C₁₄ alkyl group; R₄ is suitably a -C00- group; and n is suitably 1-4, preferably 1-2.
- If two or more of the groups R₁, R₂ and R₃ form a heterocyclic ring with the nitrogen atom of the amphoteric compound, the ring so formed is suitably an imidazoline ring.
- The amphoteric compound used is most preferably an alkyl betaine, especially lauryl betaine.
- The relative proportions of the chlorite and the ampholeric compound in the composition is suitably in the range of 1:0.1 to 1:0.9 w/w respectively, preferably 1:0.4 to 1:0.7 w/w.
- The compositions of the present invention are preferably used as aqueous solutions. However, such solutions may optionally contain a water-miscible secondary solvent, e.g. an alcohol or a glycol to enhance the freeze-thaw properties of the composition.
- The treatment of the contaminated feed with the compositions of the present invention can be effected at temperatures ranging from below ambient to about 150°C. The scavenger formulations of the present invention are particularly effective in treating wet crude oil, i.e. crudes containing 5 - 95% w/w water and containing hydrogen sulphide at levels of 1 - 1000 ppm at a temperature e.g. in the range from 15-60°C and a pH e.g. in the range of 4.0-6.9. These formulations are substantially free of any corrosive effects under these conditions.
- A feature of the present inventions is that the use of these scavenger formulations have significant advantages over those used hitherto: For instance these compositions are:
- i) Easy to use and transport offshore
- ii) Effective in the wide variety of conditions seen offshore
- iii) Fast reacting
- iv) Non-corrosive by-products
- v) Cost effective
- vii) Environmentally acceptable
- The present invention is further illustrated with reference to the following Examples.
- Corrosion rate measurements were performed using LPR (linear polarisation resistance) method. A rig was constructed from polytetrafluroethylene (PTFE), nylon and silicone rubber. The rig contained two separate corrosion cells, connected in series but some distance apart. Each cell contained three concentric, mild steel electrodes, 8.6cm² surface area, with PTFE spacers.
- A multichannel peristaltic pump controlled the addition of all the chemicals through the rig. Concentrations of the various reactants were adjusted to give the desired final concentration of sulphide and scavenger composition in the flowing stream. A flow rate of 45 to 50cm³ (total fluids) was set. Deareated saline water (4.3% NaCl) buffered to a pH of 4.8 with NaHCO₃ and CO₂ was treated with 35 to 40ppm w/w (in fluid) of H₂S. Corrosion rate measurements were continuously monitored at the point of injection, cell A, and further downstream, cell B. In this way the most corrosive environment (highest excess of oxidising agent) and the least corrosive environment (dynamic equilibrium of reactants) were obtained. Sample points of the untreated and the treated H₂S stream enabled assessment of the efficiency of the H₂S scavenging reaction (Iodimetric analysis, see Vogel's Textbook of Quantitative Inorganic Analysis, 4th Edition, Longmans).
- The effect of the injection of a solution that contains only sodium chlorite is shown in Table 1. The corrosion rate does not increase above that of the background until the level of the scavenger equals that required to react with all the hydrogen sulphide at this concentration the corrosion rate in the injection cell increases significantly although the downstream corrosiveness is still that of the background. Above this concentration the corrosion rate increases to unacceptable levels. In contrast, Table 2 shows that by incorporating a betaine into the formulation the corrosion rate is controlled to less than 30 mpy even when the injection rate is double that required to react with all the hydrogen sulphide.
Table 1 Corrosion Rates in Solutions which contain sodium chlorite Conditions Time (hours) Corrosion rate (mpy) Corrosion rate (mpy) Cell A Cell B NO TREATMENT 0 19 19 2.3 20 17 50% Required NaClO₂ 2.6 10 12 2.4 15 9 0% Excess NaClO₂ 3.6 37 18 4.4 60 25 50% Excess NaClO₂ 4.6 63 40 5.0 63 40 100% Excess NaClO₂ 5.1 63 63 5.5 122 122 NB. hydrogen sulphide generated in the system is 30-35 ppm. - The above experiments were carried out at ambient temperatures (15-20°C) and atomspheric pressures (at sealevel but these conditions are rarely seen in real processes occuring offshore, for this reason we undertook some experiments unsing autoclave to investigate the effect of higher temperatures (60°C) and pressures (3 bar). The results from these experiments are summarised in Table 3 where the scavenger is again added at twice the concentration required to react with all the hydrogen sulphide. In the absence of the corrosion inhibitor (NaC10₂ only) the corrosion rate increases to 86 mpy. In comparison, the incorporation of alkyl betaine (present as 17% w/v in the stock chlorite solution (25% w/v)) lowers this corrosion rate to near that of the original solution. This validates the results of earlier experiments.
Table 3 Corrosivity Measurements at 60 deg C and 3 bar Pressure. Conditions Corrosion rate (mpy) NO TREATMENT 36 NaClO₂ only 86 NaClO₂ + betaine 45 - Chlorite has been tested with and without lauryl betaine to investigate the influence if any of the corrosion inhibitor on the hydrogen sulphide scavenging ability of the product.
- Hydrogen sulphide was generated in situ in a sealed vessel containing brine (92cm³ of 4% NaC1, 0.1% NaHC0₃) and stabilised crude oil (10cm³ of forties crude), by injection of an aqueous Na₂S solution (2.6cm³ of 0.029M) and sulphuric acid (5.6cm³ of 0.05m).
- The resultant pH was 6.2 to 6.4. The H₂S scavenger was introduced into the flask and after a predetermined time interval the residual H₂S was determined by injection of 100cm³ of air through the solution and vented via a Drager tube. Experiments were all conducted at ambient temperatures.
- Typical results are given in Table 4. This table clearly shows that the acitivity of the chlorite is not comprised by the addition of the corrosion inhibitor.
- Chlorite has been tested with and without lauryl betaine to investigate the influence if any of the corrosion inhibitor on the hydrogen sulphide scavenging ability of the product.
- Hydrogen sulphide was generated in situ in a sealed vessel containing brine (92cm³ of 4% NaC1, 0.1% NaHC0₃) and stabilised crude oil (10cm³ of forties crude), by injection of an aqueous Na₂S solution (2.6cm³ of 0.029M) and sulphuric acid (5.6cm³ of 0.05m).
- The resultant pH was 6.2 to 6.4. The H₂S scavenger was introduced into the flask and after a predetermined time interval the residual H₂S was determined by injection of 100cm³ of air through the solution and vented via a Drager tube. Experiments were all conducted at ambient temperatures.
-
Claims (10)
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
GB898906406A GB8906406D0 (en) | 1989-03-21 | 1989-03-21 | Removal of sulphides |
GB8906406 | 1989-03-21 |
Publications (2)
Publication Number | Publication Date |
---|---|
EP0389150A1 true EP0389150A1 (en) | 1990-09-26 |
EP0389150B1 EP0389150B1 (en) | 1993-05-12 |
Family
ID=10653694
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP90302513A Expired - Lifetime EP0389150B1 (en) | 1989-03-21 | 1990-03-08 | Removal of sulphides |
Country Status (7)
Country | Link |
---|---|
US (1) | US5082576A (en) |
EP (1) | EP0389150B1 (en) |
DE (1) | DE69001575T2 (en) |
DK (1) | DK0389150T3 (en) |
GB (1) | GB8906406D0 (en) |
GR (1) | GR3008652T3 (en) |
NO (1) | NO901272L (en) |
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
AU652600B2 (en) * | 1990-12-07 | 1994-09-01 | Exxon Chemical Patents Inc. | Desulphurisation of hydrocarbon feedstreams with N-halogeno compounds |
Families Citing this family (8)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US5225103A (en) * | 1989-08-23 | 1993-07-06 | Hoechst Aktiengesellschaft | Aqueous aldehyde solutions for trapping hydrogen sulfide in natural gas and crude oil producing plants |
DE3927763A1 (en) * | 1989-08-23 | 1991-02-28 | Hoechst Ag | AQUEOUS ALDEHYL SOLUTIONS TO trap SULFUR HYDROGEN |
US5397708A (en) * | 1993-05-13 | 1995-03-14 | Nalco Chemical Company | Method for detection of sulfides |
US5635458A (en) * | 1995-03-01 | 1997-06-03 | M-I Drilling Fluids, L.L.C. | Water-based drilling fluids for reduction of water adsorption and hydration of argillaceous rocks |
US6258859B1 (en) * | 1997-06-10 | 2001-07-10 | Rhodia, Inc. | Viscoelastic surfactant fluids and related methods of use |
US20070119747A1 (en) * | 2005-11-30 | 2007-05-31 | Baker Hughes Incorporated | Corrosion inhibitor |
US8895482B2 (en) | 2011-08-05 | 2014-11-25 | Smart Chemical Services, Lp | Constraining pyrite activity in shale |
MX2017011103A (en) | 2015-04-01 | 2018-05-07 | Int Dioxcide Inc | Stabilized composition for combined odor control and enhanced dewatering. |
Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US1908273A (en) * | 1930-04-17 | 1933-05-09 | Mathieson Alkali Works Inc | Sweetening petroleum distillates |
FR1103465A (en) * | 1953-04-29 | 1955-11-03 | Bataafsche Petroleum | Light hydrocarbon oil treated with hypochlorite |
US4594147A (en) * | 1985-12-16 | 1986-06-10 | Nalco Chemical Company | Choline as a fuel sweetener and sulfur antagonist |
GB2170220A (en) * | 1985-01-25 | 1986-07-30 | Nl Petroleum Services | Treatment of hydrocarbon fluids subject to contamination by sulfide compounds |
Family Cites Families (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CA1207269A (en) * | 1982-07-26 | 1986-07-08 | Atlantic Richfield Company | Method of treating oil field produced fluids with chlorine dioxide |
US4473115A (en) * | 1982-09-30 | 1984-09-25 | Bio-Cide Chemical Company, Inc. | Method for reducing hydrogen sulfide concentrations in well fluids |
-
1989
- 1989-03-21 GB GB898906406A patent/GB8906406D0/en active Pending
-
1990
- 1990-03-08 DE DE9090302513T patent/DE69001575T2/en not_active Expired - Fee Related
- 1990-03-08 EP EP90302513A patent/EP0389150B1/en not_active Expired - Lifetime
- 1990-03-08 DK DK90302513.8T patent/DK0389150T3/en active
- 1990-03-09 US US07/491,355 patent/US5082576A/en not_active Expired - Fee Related
- 1990-03-20 NO NO90901272A patent/NO901272L/en unknown
-
1993
- 1993-05-28 GR GR920403158T patent/GR3008652T3/el unknown
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US1908273A (en) * | 1930-04-17 | 1933-05-09 | Mathieson Alkali Works Inc | Sweetening petroleum distillates |
FR1103465A (en) * | 1953-04-29 | 1955-11-03 | Bataafsche Petroleum | Light hydrocarbon oil treated with hypochlorite |
GB2170220A (en) * | 1985-01-25 | 1986-07-30 | Nl Petroleum Services | Treatment of hydrocarbon fluids subject to contamination by sulfide compounds |
US4594147A (en) * | 1985-12-16 | 1986-06-10 | Nalco Chemical Company | Choline as a fuel sweetener and sulfur antagonist |
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
AU652600B2 (en) * | 1990-12-07 | 1994-09-01 | Exxon Chemical Patents Inc. | Desulphurisation of hydrocarbon feedstreams with N-halogeno compounds |
Also Published As
Publication number | Publication date |
---|---|
NO901272L (en) | 1990-09-24 |
DE69001575D1 (en) | 1993-06-17 |
DK0389150T3 (en) | 1993-06-07 |
GB8906406D0 (en) | 1989-05-04 |
US5082576A (en) | 1992-01-21 |
EP0389150B1 (en) | 1993-05-12 |
NO901272D0 (en) | 1990-03-20 |
DE69001575T2 (en) | 1993-08-26 |
GR3008652T3 (en) | 1993-11-30 |
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